Hydrocarbon products

ABSTRACT

A hydrocarbon product having at least 0.1 grams per gram of hydrocarbon product having a boiling range distribution from an initial boiling point to approximately 739° C. wherein the hydrocarbon products are further characterized by an infrared spectroscopy reference peak, centered between approximately 1445 cm −1  and 1465 cm −1 , a first infrared spectroscopy peak between approximately 1310 cm −1  and 1285 cm −1 , wherein the height of the first infrared spectroscopy peak is at least approximately 28% of the height of the infrared spectroscopy reference peak and a second infrared spectroscopy peak between approximately 1135 cm −1  and 1110 cm −1 , wherein the height of the second infrared spectroscopy peak is at least approximately 22% of the height of the infrared spectroscopy reference peak.

FIELD OF THE TECHNOLOGY

The following relates generally to a hydrocarbon product havingrelatively low viscosity and low density while containing a significantamount of residue and micro-carbon residue.

BACKGROUND

Crude oil contains heteroatoms such as sulfur, nitrogen, nickel,vanadium and acidic oxygenates in quantities that negatively impact therefinery processing of the crude oil fractions. Light crude oils orcondensates contain heteroatoms in concentrations as low as 0.001 wt %.In contrast, heavy crude oils contain heteroatoms as high as 5-7 Wt %.The heteroatom content of crude oil increases with increasing boilingpoint and the heteroatom content increases with decreasing API gravity.These impurities must be removed during refining operations to meet theenvironmental regulations for the final product specifications (e.g.,gasoline, diesel, fuel oil) or to prevent the contaminants fromdecreasing catalyst activity, selectivity, and lifetime in downstreamrefining operations. Contaminants such as sulfur, nitrogen, tracemetals, and total acid number (TAN) in the crude oil fractionsnegatively impact these downstream processes, including hydrotreating,hydrocracking and fluid catalytic cracking (FCC) to name just a few.These contaminants are present in the crude oil fractions in varyingstructures and concentrations.

Crudes that have one or more unsuitable properties that do not allow thecrudes to be economically transported, or processed using conventionalfacilities, are commonly referred to as “disadvantaged crudes.”Disadvantaged crudes often contain relatively high levels of residue.Such crudes tend to be difficult and expensive to transport and/orprocess using conventional facilities. High residue crudes may betreated at high temperatures to convert the crude to coke.Alternatively, high residue crudes are typically treated with water athigh temperatures to produce less viscous crudes and/or crude mixtures.During processing, water removal from the less viscous crudes and/orcrude mixtures may be difficult using conventional means.

Disadvantaged crudes may include hydrogen deficient hydrocarbons. Whenprocessing of hydrogen deficient hydrocarbons using previously knownmethods, consistent quantities of hydrogen are generally needed to beadded, particularly if unsaturated fragments resulting from crackingprocesses are produced. Hydrogenation during processing, which typicallyinvolves the use of an active hydrogenation catalyst, may be needed toinhibit unsaturated fragments from forming coke. Hydrogen is costly toproduce and/or costly to transport to treatment facilities.

Coke may form and/or deposit on catalyst surfaces at a rapid rate duringprocessing of disadvantaged crudes. It may be costly to regenerate thecatalytic activity of a catalyst contaminated by coke. High temperaturesused during regeneration may also diminish the activity of the catalystand/or cause the catalyst to deteriorate. Disadvantaged crudes mayinclude acidic components that contribute to the total acid number (TAN)of the crude feed. Disadvantaged crudes with a relatively high TANs maycontribute to corrosion of metal components during transporting and/orprocessing of the disadvantaged crudes. Removal of acidic componentsfrom disadvantaged crudes may involve chemically neutralizing acidiccomponents with various bases. Alternately, corrosion-resistant metalsmay be used in transportation equipment and/or processing equipment. Theuse of corrosion-resistant metal often involves significant expense, andthus, the use of corrosion-resistant metal in existing equipment may notbe desirable. Another method to inhibit corrosion may involve additionof corrosion inhibitors to disadvantaged crudes before transportingand/or processing of the disadvantaged crudes. The use of corrosioninhibitors may negatively affect equipment used to process the crudesand/or the quality of products produced from the crudes. Disadvantagedcrudes may contain relatively high amounts of metal contaminants, forexample, nickel, vanadium, and/or iron. During processing of suchcrudes, metal contaminants, and/or compounds of metal contaminants, maydeposit on a surface of the catalyst or the void volume of the catalyst.Such deposits may cause a decline in the activity of the catalyst.

Disadvantaged crudes often include organically bound heteroatoms (forexample, sulfur, oxygen, and nitrogen). Organically bound heteroatomsmay, in some situations, have an adverse effect on catalysts. Alkalimetal salts and/or alkaline-earth metal salts have been used inprocesses for desulfurization of residue. These processes tend to resultin poor desulfurization efficiency, production of oil insoluble sludge,poor demetallization efficiency, formation of substantially inseparablesalt-oil mixtures, utilization of large quantities of hydrogen gas,and/or relatively high hydrogen pressures.

Some processes for improving the quality of crude include adding adiluent to disadvantaged crudes to lower the weight percent ofcomponents contributing to the disadvantaged properties. Adding diluent,however, generally increases costs of treating disadvantaged crudes dueto the costs of diluent and/or increased costs to handle thedisadvantaged crudes. Addition of diluent to disadvantaged crude may, insome situations, decrease stability of such crude.

Other processes for improving the quality of crude includehydrocracking. Hydrocracking, however, generally has a high costassociated with expensive catalysts and pressure vessels. In addition,hydrocracking, under certain conditions, may also create olefins.Olefins are unstable and may, in some situations, decrease the stabilityof crude. Therefore, olefin-containing crudes may require the additionof expensive additives to permit transportation in pipelines. See U.S.Pat. No. 3,136,714 to Gibson et al.; U.S. Pat. No. 3,558,747 to Gleim etal.; U.S. Pat. No. 3,847,797 to Pasternak et al.; U.S. Pat. No.3,948,759 to King et al.; U.S. Pat. No. 3,957,620 to Fukui et al.; U.S.Pat. No. 3,960,706 to McCollum et al.; U.S. Pat. No. 3,960,708 toMcCollum et al.; U.S. Pat. No. 4,119,528 to Baird, Jr. et al.; U.S. Pat.No. 4,127,470 to Baird, Jr. et al.; U.S. Pat. No. 4,224,140 to Fujimoriet al.; U.S. Pat. No. 4,437,980 to Heredy et al.; U.S. Pat. No.4,591,426 to Krasuk et al.; U.S. Pat. No. 4,665,261 to Mazurek; U.S.Pat. No. 5,064,523 to Kretschmar et al.; U.S. Pat. No. 5,166,118 toKretschmar et al.; U.S. Pat. No. 5,288,681 to Gatsis; U.S. Pat. No.6,547,957 to Sudhakar et al.; U.S. Pat. No. 7,598,426 to Fang et al.;U.S. Pat. No. 7,648,625 to Bhan et al.; U.S. Pat. No. 7,678,264 to Bhan;U.S. Pat. No. 7,749,374 to Bhan et al.; U.S. Pat. No. 7,918,992 to Bhan;U.S. Pat. No. 8,088706 to Domokos et al.; U.S. Pat. No. 8,372,777 toBhan et al.; U.S. Pat. No. 8,409,541 to Reynolds et al.; U.S. Pat. No.8,450,538 to Bhan et al.; U.S. Pat. No. 8,481,450 to Bhan; U.S. Pat. No.8,492,599 to Bhan et al.; U.S. Pat. No. 8,530,370 to Donaho et al.; U.S.Pat. No. 8,562,817 to Milam et al.; U.S. Pat. No. 8,562,818 to Milam etal.; U.S. Pat. No. 8,608,946; and U.S. Patent Application PublicationNos. 20030000867 to Reynolds; 20030149317 to Rendina; 20060231456 toBhan; 20060231457 to Bhan; 2006023476 to Bhan; 20070000810 to Bhan etal.; 20070295646 to Bhan et al.; 20080083650 to Bhan et al.; 20080087575to Bhan et al.; 20080135449 to Bhan et al.; 20090188836 to Bhan et al;20100055005 to Bhan et al.; 20100098602 to Bhan et al.; 20110178346 toMilam et al.; and 20110192762 to Wellington et al, all of which areincorporated herein by reference, describe various processes and systemsused to treat crudes. The process, systems, and catalysts described inthese patents, however, have limited applicability because of many ofthe technical problems set forth above.

In sum, disadvantaged crudes generally have undesirable properties, forexample, relatively high residue, a tendency to corrode equipment,and/or a tendency to consume relatively large amounts of hydrogen duringtreatment. Other undesirable properties include relatively high amountsof undesirable components including relatively high TANs, organicallybound heteroatoms, and/or metal contaminants. Such properties tend tocause problems in conventional transportation and/or treatmentfacilities, including increased corrosion, decreased catalyst life,process plugging, and/or increased usage of hydrogen during treatment.Thus, there is a significant economic and technical need for improvedsystems, methods, and/or catalysts for conversion of disadvantagedcrudes, and other hydrocarbons into hydrocarbon products and crudeproducts with properties that are more desirable.

SUMMARY OF THE TECHNOLOGY

A first embodiment of this disclosure relates generally to a hydrocarboncomposition comprising at least 0.1 grams per gram of hydrocarbonproduct having a boiling range distribution from an initial boilingpoint to approximately 739° C., an infrared spectroscopy reference peak,centered between approximately 1445 cm−1 and 1465 cm−1, a first infraredspectroscopy peak between approximately 1310 cm−1 and 1285 cm−1, whereinthe height or area of the first infrared spectroscopy peak is at leastapproximately 28% of the height or area of the infrared spectroscopyreference peak and a second infrared spectroscopy peak betweenapproximately 1135 cm−1 and 1110 cm−1. wherein the height or area of thesecond infrared spectroscopy peak is at least approximately 22% of theheight or area of the infrared spectroscopy reference peak.

A second embodiment of this disclosure relates generally to ahydrocarbon product comprising at most 0.3 grams per gram of thehydrocarbon product is insoluble in n-heptane, at least 0.1 grams pergram of the hydrocarbon product has a boiling point greater than 738°C., an infrared spectroscopy reference peak, centered betweenapproximately 1445 cm⁻¹ and 1465 cm⁻¹, a first infrared spectroscopypeak between approximately 1135 cm⁻¹ and 1110 cm⁻¹, wherein the heightor area of the first infrared spectroscopy peak is at leastapproximately 22% of the height or area of the infrared spectroscopyreference peak and a second infrared spectroscopy peak betweenapproximately 1040 cm^(−l)and 1000 cm⁻¹, wherein the height or area ofthe second infrared spectroscopy peak is at least approximately 22% ofthe height or area of the infrared spectroscopy reference peak.

A third embodiment of this disclosure relates generally to a hydrocarbonproduct comprising 0.01 to 0.25 grams of hydrocarbons per gram of thehydrocarbon product having a boiling range distribution from an IBP toapproximately 204° C., an infrared spectroscopy reference peak, centeredbetween approximately 1445 cm⁻¹ and 1465 cm⁻¹, a first infraredspectroscopy peak between approximately 1310 cm⁻¹ and 1285 cm⁻¹, whereinthe height or area of the third infrared spectroscopy peak is at leastapproximately 28% of the height or area of the infrared spectroscopyreference peak, and a second infrared spectroscopy peak betweenapproximately 1040 cm⁻¹ and 1000 cm⁻¹, wherein the height or area of thesecond infrared spectroscopy peak is at least approximately 22% of theheight or area of the infrared spectroscopy reference peak.

BRIEF DESCRIPTION OF THE DRAWINGS

Some of the embodiments will be described in detail, with reference tothe following figures, wherein like designations denote like members,wherein:

FIG. 1 a depicts a flowchart describing an embodiment of a method ofoxidative desulfurization of a hydrocarbon feed.

FIG. 1 b depicts a flowchart describing an embodiment of treating asulfone and/or sulfoxide rich hydrocarbon feed.

FIG. 2 depicts how the selectivity of a reaction between a sulfoneand/or sulfonate and caustic may be manipulated using an alcoholysisreaction to form more desirable products using a selectivity promoter.

FIG. 3 depicts multiple embodiments of an alcoholysis reaction between asulfone, caustic and selectivity promoter and provides embodiments ofthe reaction products thereof.

FIG. 4 depicts an embodiment of a reaction mechanism for forming asulfonate intermediate from a sulfone substrate.

FIG. 5 depicts an embodiment of a biphasic reaction mechanism forforming a hydrocarbon product and a sulfate salt.

FIG. 6 a depicts a comparative graphical representation of multipleembodiments of a simulated distillation (SIMDIS) of multiple hydrocarbonfeeds and their predicted boiling point distributions.

FIG. 6 b depicts a graphical representation of a SIMDIS of the crudefeed boiling point distribution provided in FIG. 6 a.

FIG. 6 c depicts a graphical representation of a SIMDIS of thesulfoxidized crude oil boiling point distribution provided in FIG. 6 a.

FIG. 6 d depicts a graphical representation of a SIMDIS of thehydrocarbon products of the low heteroatom removal boiling pointdistribution provided in FIG. 6 a.

FIG. 6 e depicts a graphical representation of a SIMDIS of thehydrocarbon products of the mild heteroatom removal boiling pointdistribution provided in FIG. 6 a.

FIG. 6 f depicts a graphical representation of a SIMDIS of thehydrocarbon products of the moderate heteroatom removal boiling pointdistribution provided in FIG. 6 a.

FIG. 7 a depicts a graphical representation of infrared spectroscopy ofone embodiment of a hydrocarbon feed.

FIG. 7 b depicts a graphical representation of an infrared spectroscopyof one embodiment of a sulfoxidized intermediate hydrocarbon stream.

FIG. 7 c depicts a graphical representation of an infrared spectroscopyof one embodiment of a hydrocarbon product.

FIG. 7 d depicts a graphical comparison of the infrared spectroscopiesof FIG. 7 a and FIG. 7 b.

FIG. 7 e depicts a graphical comparison of infrared spectroscopies ofFIG. 7 a and FIG. 7 c.

FIG. 7 f depicts a graphical comparison of infrared spectroscopies ofFIG. 7 b and FIG. 7 c.

DETAILED DESCRIPTION OF THE DISCLOSURE

A detailed description of the hereinafter described embodiments of thedisclosed apparatus and method are presented herein by way ofexemplification and not limitation with reference to the Figures.Although certain embodiments are shown and described in detail, itshould be understood that various changes and modifications may be madewithout departing from the scope of the appended claims. The scope ofthe present disclosure will in no way be limited to the number ofconstituting components, the materials thereof, the shapes thereof, therelative arrangement thereof, etc., and are disclosed simply as anexample of embodiments of the present disclosure.

As a preface to the detailed description, it should be noted that, asused in this specification and the appended claims, the singular forms“a”, “an” and “the” include plural referents, unless the context clearlydictates otherwise.

Certain embodiments are described in detail below. Terms used herein maybe defined as follows:

“ASTM” refers to American Standard Testing and Materials.

“API gravity” refers to American Petroleum Institute gravity (“APIgravity”) at 15.5° C., unless stated otherwise. API gravity may bedetermined by ASTM Method D6822 or equivalent method. API gravity, is ameasure of how heavy or light a petroleum liquid is compared to water.If its API gravity is greater than 10, it is lighter and floats onwater; if less than 10, it is heavier and sinks API gravity is thus aninverse measure of the relative density of a petroleum liquid and thedensity of water, but it is used to compare the relative densities ofpetroleum liquids. For example, if one petroleum liquid floats onanother and is therefore less dense, it has a greater API gravity.Although mathematically, API gravity has no units, it is neverthelessreferred to as being in “degrees”. API gravity is gradated in degrees ona hydrometer instrument.

The ratio of atomic hydrogen to atomic carbon present in a hydrocarbonfeed and the crude product may be determined by ASTM Method D5291 orequivalent method.

Boiling range distributions for the hydrocarbon feed, the total product,and/or the crude product may be determined by ASTM Method D5307 orequivalent method thereof, unless otherwise mentioned.

“Biphasic” means a chemical system that contains two separate anddistinct immiscible chemical phases. These phases may be any immisciblesubstances, including gas-liquid, gas-solid, liquid-liquid andliquid-solid phases.

Boiling range distributions for hydrocarbons and hydrocarbon containingmaterial may be as determined by ASTM Method D5307 or equivalent method.The content of a particular boiling range may be characterized by thegrams of the hydrocarbon boiling within the specific range per 1 gram ofthe total hydrocarbon mixture of a hydrocarbon feed or hydrocarbonproduct. For example, if a hydrocarbon product produces 0.3 g ofhydrocarbon having a boiling point within a range of 204-260° C., pergram of hydrocarbon product, means that for every gram of hydrocarbonproduct produced, 0.3 g of the hydrocarbon product includes hydrocarbonsthat boil within the 204-260° C. boiling point range.

“C₅ asphaltenes” refers to asphaltenes that are insoluble in n-pentane.C₅ asphaltene content may be determined by ASTM Method D2007 orequivalent thereof.

“C₇ asphaltenes” refers to asphaltenes that are insoluble in n-heptane.C₇ asphaltene content may be determined by ASTM Method D3279.

“Carbon to hydrogen ratio” (C/H ratio) refers to the ratio of the amountof atomic carbon present in a substance compared with the amount ofatomic hydrogen present. For example a hydrocarbon product having a C/Hratio of 1.5 parts carbon for every one part hydrogen may have a C/Hratio of 1.5/1. Alternatively, the C/H ratio may reduce the fractionwhere applicable. Using the previous example, the C/H ratio may simplybe referred to as a C/H ratio of 1.5, because 1.5 divided by 1 equals1.5.

“Diesel” refers to hydrocarbons with a boiling range distribution fromapproximately 250° C. up to approximately 350° C. as determined inaccordance with ASTM Method D5307 or equivalent method. Diesel contentmay be determined by the quantity of hydrocarbons having a boiling rangebetween 250-350° C. relative to the quantity of hydrocarbons as measuredby the boiling range distribution.

“Distillate” refers to hydrocarbons with a boiling range distributionfrom approximately 200-350° C. as determined by ASTM Method D5307.Distillates may include diesel and kerosene.

“Gasolines” refers to hydrocarbons with a boiling range distributionfrom approximately 40 to 250° C. in accordance with ASTM Method D5307 orequivalent method. Gasoline hydrocarbons may be short carbon chainshaving approximately 4-12 carbons per molecule. Gasoline content may bedetermined by the quantity of hydrocarbons having a boiling rangebetween 40 to 250° C. relative to the quantity of hydrocarbons asmeasured by the boiling range distribution.

“Hydrogen to carbon ratio” (H/C) ratio is the reciprocal of the C/Hratio. It refers to the amount of atomic hydrogen present compared withthe amount of atomic carbon present in a substance. For example, usingthe C/H ratio above, the H/C ratio would be 1/1.5. The H/C ratio mayalso be simplified by reducing the fraction to a decimal or wholenumber. For example, H/C ratio of 1/1.5 may simply be referred to as anH/C ratio of 0.67.

“Group X metal(s)” refers to one or more metals of a column of thePeriodic Table of Elements in which X corresponds to a column number ofthe Periodic Table. For example, “group 4 metal(s)” refers to one ormore metals from column 4 of the Periodic Table (ex. Ti, Zr, Hf, Rf). A“metal” may refer to any element of the periodic table residing ingroups 1-12 (excluding hydrogen) of the periodic table of elements, plusaluminum, gallium, indium, thallium, tin, lead, bismuth and polonium.

“Group X element(s)” refers to one or more elements located in a columnon the Periodic Table of Elements, wherein X corresponds to one or morecolumn numbers recited (ex. columns 13-18). For example, a column 13element may include B, Al, Ga, In, Tl, and Uut.

“Contaminated hydrocarbon stream” is a mixture of hydrocarbonscontaining heteroatom constituents.

“Content” refers to the weight of a component (for example heteroatomcontent) in a substrate. An example of a substrate may be a hydrocarbonfeed, a reaction product and/or crude product. The content may beexpressed as a weight fraction or weight % (wt %) which may becalculated as the

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For example, “metal content” may be expressed as a weight percent (wt %)wherein the metal content may be determined using the formula:

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of metal content.

“Hydrocarbon(s)” refers to a substance that has primary components ofhydrogen and carbon. Hydrocarbons may include, but are not limited toboth saturate and unsaturated forms of aromatic hydrocarbons, alkanes,alkenes, alkynes, aryls and cycloalkanes.

“Hydrocarbon feed” refers to a feed that includes hydrocarbons. Thehydrocarbon feed may include, but is not limited to, crudes, heavy orextra heavy crudes, crude oils containing significant quantities ofresidue or pitch, bitumen, disadvantaged crudes, contaminatedhydrocarbon streams, hydrocarbons derived from tar sands, shale oil,crude atmospheric residues, asphalts, hydrocarbons derived fromliquefying coal and hydrocarbons obtained from a refinery process ormixtures thereof. The hydrocarbon feed may include hydrocarbons and amixture of one or more heteroatoms. Common sulfur containingcontaminants to a hydrocarbon feed may be mercaptans, sulfides,disulfides, thiophenes, benzothiophenes, dibenzothiophenes andbenzo-naphthothiophenes.

“Initial boiling point” (IBP) refers to the point where hydrocarbons ora mixture of hydrocarbons first begin to boil. The initial boiling pointmay vary depending on the composition of the mixture. Depending on thecomposition of hydrocarbons, the initial boiling point of thehydrocarbons may range from less than 30° C. up to approximately 739° C.In some embodiments, the IBP may be less than 30° C., less than 50° C.,less than 70° C., or less than 100° C. In other embodiments, the IBP maybe between 30-50° C. or 50 to 100° C. In alternative embodiments, theIBP may be less than 150° C., less than 200° C., less than 250° C., lessthan 350° C. or less than 450° C. The IBP may be between 150-250° C.,250-350° C. or between 350-450° C. Other embodiments containing highquantities of hydrocarbons having longer chains, may have a IBP between450 to 750° C. In some instances the IBP may be less than 450° C., lessthan 550° C., less than 650° C. or less than 750° C. The IBP may bebetween 450-550° C., 550-650° C., 650-750° C. or even greater than 750°C. in some embodiments, for example those embodiments containing ahigher quantity of bitumen or asphalt.

As the carbon chains of the crude oil fractions become longer, theboiling point of the fraction may become higher, thus as the compositioncontains short chained hydrocarbons, the initial boiling point maydecrease, whereas in a composition having less short chainedhydrocarbons, the initial boiling point may rise. For example, a mixtureof hydrocarbons including petroleum gas fractions having a small alkanesbetween 1-4 carbon atoms per molecule may have an initial boiling pointof 40° C. or less. In a hydrocarbon mixture including naphtha, having amixture of hydrocarbons between 5-9 carbon atoms per molecule, thenaphtha portion may have a boiling point between 60-100° C., wherein theboiling point may be between 60-69° C., 70-79° C., 80-89° C. and/or90-100° C. In a hydrocarbon mixture including gasoline hydrocarbons,such as alkanes and cycloalkanes, having carbon chains between 4-12atoms of carbon per molecule, the gasoline fraction may have an boilingpoint between approximately 30-250° C., wherein the boiling point may bebetween 40-59° C., 60-79° C., 80-99° C., 100-149° C., 150-199° C. and/or200-250° C. In a hydrocarbon mixture including kerosene, the keroseneportion may include alkanes having a carbon chain length between 10-18carbon atoms per molecule and/or aromatic hydrocarbons. The kerosenefractions may have a boiling point between approximately 175-325° C.,wherein the boiling point may be 175-199° C., 200-249° C., 250-299° C.and/or 300-325° C.

Some hydrocarbon mixture may include a gas oil fraction which may beused for diesel fuel and heating oil. The gas oil fraction may includealkanes having 12 or more carbon atoms per molecule. The gas oilfraction may have a boiling point between 250-350° C. In someembodiments, the boiling point may be 250-274° C., 275-299° C., 300-324°C. and/or 325-350° C. Hydrocarbon products may include a lubricating oilfraction, having long hydrocarbons between 20 to 50 carbon atoms permolecule. The lubricating oil fraction may include alkanes, cycloalkanesand aromatics and the lubricating oil fractions may have a boiling pointbetween 300-370° C., wherein the boiling point may be between 300-324°C., 325-349° C. and/or 350-370° C. A hydrocarbon product may alsoinclude in its mixture of hydrocarbons a heavy gas or fuel oil fractionhaving long chains of carbon atoms between approximately 20-70 carbonatoms per molecule. The heavy gas or fuel oil fraction may have aboiling point between approximately 370-600° C., wherein the boilingpoint may be between 370-399° C., 400-449° C., 450-499° C., 500-549° C.and/or 550-600° C.

“Kerosene” refers to hydrocarbons with a boiling point distributionbetween approximately 175°-325° C. at a pressure of 0.101 MPa. Kerosenecontent may be determined by the quantity of hydrocarbons having aboiling range from 204° C. to 260° C. at a pressure of 0.101 MParelative to a total quantity of hydrocarbons as measured by boilingrange distribution in accordance with ASTM Method D5307 or an equivalentmethod thereof.

“Naphtha” refers to hydrocarbon components with a boiling rangedistribution from approximately 38° C. to 204° C. at a pressure of 0.101MPa. Naphtha content may be determined by the quantity of hydrocarbonshaving a boiling range relative to a total quantity of hydrocarbons asmeasured by boiling range distribution in accordance with ASTM MethodD5307. The content of hydrocarbon components, for example parafins,iso-parafins, olefins, naphthanenes and aromatics in naphtha may bedetermined by ASTM Method D6730 or equivalent method.

“n-Paraffin” refer to normal (straight chain) saturated hydrocarbons.

“Olefins” or “olefinic hydrocarbons” refer to hydrocarbon compounds withnon-aromatic carbon-carbon double bonds. Types of olefins may include,but are not limited to cis, trans, internal, terminal, branched andlinear.

“Periodic Table” refers to the Periodic Table as specified by theInternational Union of Pure and Applied Chemistry (IUPAC).

“STP” as used herein refers to standard temperature and pressure, whichis 25° C. and 0.101 MPa.

“Liquid mixture” refers to a composition that includes one or morecompounds that are liquid at standard temperature and pressure (25° C.,0.101 MPa, hereinafter referred to as “STP”), or a composition thatincludes a combination of one of more compounds that are liquid at STPwith one or more compounds that are solids at STP.

“Organometallic” refers to compound that may include an organic compoundbonded or complexed with a metal of the Periodic Table. “Organometalliccontent” refers to the total content of metal in the organometalliccompounds.

“Promoted caustic visbreaker” refers to a heated reactor that contains acaustic and a selectivity promoter that react with oxidized heteroatomsto remove sulfur, nickel, vanadium, iron and other contaminants orheteroatoms, increase API gravity, decrease viscosity, and decreasestotal acid number.

“Residue” or residual refers to a hydrocarbon that has a boiling rangedistribution above 538° C. (1000° F.), as determined by ASTM MethodD5307 or an equivalent method thereof. The residual portion of ahydrocarbon mixture of a hydrocarbon product may include coke, asphalt,tar and waxes. The hydrocarbon fraction may include multi-ringedstructures having a carbon chain of approximately 70 or more carbonatoms per molecule. In some embodiments, residual portion of ahydrocarbon mixture may have a boiling point greater than 538° C.,greater than 600° C., greater than 700° C., greater than 800° C.,greater than 1000° C., greater than 1200° C., greater than 1500° C.,and/or greater than 1800° C.

“Sulfoxidation” may refer to a reaction or conversion, whether or notcatalytic, that produces organo-sulfoxide, organo-sulfone,organo-sulfonate, or organo-sulfonic acid compounds (and/or mixturesthereof) from organosulfur compounds.

“TAN” refers to a total acid number expressed as milligrams (“mg”) ofKOH per gram (“g”) of sample. TAN may be determined by ASTM Method D664or an equivalent method thereof. The TAN is a measurement of aciditythat is determined by the amount of potassium hydroxide in milligramsthat is needed to neutralize the acids in one gram of oil. It is animportant quality measurement of crude oil. The TAN value indicates tothe crude oil refinery the potential of corrosion problems. It isusually the naphthenic acids in the crude oil that causes corrosionproblems.

“Total base number (TBN)” is a measure of a petroleum product's reservealkalinity. It is measured in milligrams of potassium hydroxide per gram(mg KOH/g). TBN determines how effective the control of acids formedwill be during the combustion process. The higher the TBN, the moreeffective it is in suspending wear-causing contaminants and reducing thecorrosive effects of acids and acidic byproducts over an extended periodof time. TBN may be determined using ASTM D2896 or an equivalent methodthereof.

“Used catalyst” or “spent catalyst” refers to one or more catalysts thathave been contacted with a hydrocarbon feed. In some embodiments, a usedcatalyst may be regenerated and re-contacted with the hydrocarbon feed.

“VGO” refers to hydrocarbons with a boiling range distribution between343° C. (650° F.) and 538° C. (1000° F.) at 0.101 MPa. VGO content maybe determined by ASTM Method D5307 or equivalent method thereof.

“Viscosity” refers to kinematic viscosity at 37.8° C. (100° F.), unlessotherwise indicated. Viscosity may be determined using ASTM Method D445or an equivalent method thereof.

Crudes may be produced and/or retorted from hydrocarbon containingformations. Crudes may generally be a solid, semi-solid, and/or liquid.Crudes may include crude oil. A crude oil may be further stabilized.Stabilization of crudes may include the removal of non-condensablegases, water, salts, or combinations thereof from the crude. Theresulting crude post-stabilization may be referred to as stabilizedcrude. Stabilization may occur at, or proximate to, the crude productionsite and/or at the site of retorting.

Stabilized crudes may or may not have been distilled and/or fractionallydistilled in a treatment facility to produce multiple components withspecific boiling range distributions (for example, naphtha, distillates,VGO, and/or lubricating oils). Distillation includes, but is not limitedto, atmospheric distillation methods and/or vacuum distillation methods.Undistilled and/or unfractionated stabilized crudes may includecomponents that have a carbon number above 4 in quantities of at least0.5 grams of components per gram of crude. Examples of stabilized crudesinclude whole crudes, topped crudes, desalted crudes, desalted toppedcrudes, or combinations thereof. “Topped” refers to a crude that hasbeen treated such that at least some of the components having a boilingpoint below 35° C. at 0.101 MPa (95° F. at 1 atm) have been removed.Typically, topped crudes will have a content of at most 0.1 grams, atmost 0.05 grams, or at most 0.02 grams of such components per gram ofthe topped crude.

Some crudes may have one or more unsuitable properties that render thecrudes disadvantaged. The properties of a disadvantaged crude mayinclude a TAN of at least 0.1, at least 0.3, at least 0.5, at least 1.0or at least 2.0; a viscosity of at least 10 centistokes (cSt); APIgravity of at most 19, at most 15 or at most 10; a total heteroatomcontent of at least 0.005 grams of heteroatom per gram of crude; aresidue content of at least 0.01 grams of residue per gram of crude; acontent of metals in metal salts of organic acids of at least 0.0001grams of metals per gram of crude; or a combination of propertiesthereof. In some embodiments the disadvantaged crude may also have anoxygen content of at least 0.005 grams of oxygen per gram ofdisadvantaged crude or a C₇ asphaltene content of at least 0.04 grams ofC₇ per gram of the disadvantaged crude.

Embodiments of a disadvantaged crude may include at least 0.2 grams ofresidue, at least 0.3 grams of residue, at least 0.5 grams of residue,or at least 0.9 grams of residue per gram of disadvantaged crude.Embodiments of a disadvantaged crude may have a TAN in the range from0.1 to 20, while in alternative embodiments, the TAN may range from 0.3to 10 or 0.4 to 5. Disadvantaged crudes may also include a sulfurcontent of at least 0.005 grams per gram of disadvantaged crude.

Disadvantaged crudes may include at least 0.001 grams of hydrocarbonsper grams of disadvantaged crudes having a boiling range distributionbetween 95° C. and 200° C. at 0.101 MPa; at least 0.001 grams ofhydrocarbons per gram of disadvantaged crude with a boiling rangedistribution between 200° C. and 300° C. at 0.101 MPa; at least 0.001grams hydrocarbons per gram of crude with a boiling range distributionbetween 300° C. and 400° C. at 0.101 MPa; and at least 0.001 grams ofhydrocarbons per gram of disadvantaged crude with a boiling rangedistribution between 400° C. and 650° C. at 0.101 MPa.

Examples of locations that may have disadvantaged crudes that might betreated using the processes described herein include, but are notlimited to, crudes from the U.S. Gulf Coast and southern California,Canadian Oil sands, Brazil's Santos and Campos basins, Egyptian Gulf ofSuez, Chad, United Kingdom North Sea, Angola Offshore, Chinese BohaiBay, Venezuelan Zulia, Malaysia, and Indonesia Sumatra. Treatment ofdisadvantaged crudes using oxidative desulfurization and heteroatomremoval may enhance the properties of the hydrocarbons present in crudesor disadvantaged crudes. The resulting hydrocarbon products from themethods described herein may make the crude products or disadvantagedcrudes products easier and economically more viable to transport and ortreat.

Referring to FIG. 1 a, depicting an embodiment 100 of a system andmethod of oxidative desulfurization 100 of a hydrocarbon feed 101.Hydrocarbon feed 101 may also be referred to as a heteroatom-containinghydrocarbon feed, or a contaminated hydrocarbon stream. Embodiments ofthe hydrocarbon feed 101 may include any element in addition to thecarbon and hydrogen of the hydrocarbon. Heteroatoms contaminating thehydrocarbon feed may include, but is not limited to compounds containingsulfur, oxygen, nitrogen, nickel, vanadium, iron or other transitionmetals and combinations of compounds thereof. The heteroatom containinghydrocarbon feed may contain at least 15 weight parts per million (wppm)vanadium and at least 5 wppm nickel. The heteroatom containinghydrocarbon feed may also contain at least 0.20 Wt. % sulfur, or atleast 2 Wt. % sulfur, or at least 4 Wt. % sulfur; and thehydrocarbon-containing feedstock may contain at least 0.01 Wt. %nitrogen, or at least 0.4 Wt. % nitrogen.

In some embodiments, the content of the hydrocarbon feed may becharacterized by infrared spectroscopy. Embodiments of a hydrocarbonfeed tested using IR spectroscopy may exhibit one or morecharacteristics at a specific wavelength or wavenumber in comparisonwith a reference peak. Referring to embodiments depicted in FIG. 7 a,the hydrocarbon feed reference peak was exhibited between approximately1445 cm⁻¹ and 1465 cm⁻¹. The reference peak may vary depending on thecontent of the hydrocarbon feed. In some embodiments, the hydrocarbonfeed may exhibit an absorbance between 1310 cm⁻¹ and 1285 cm⁻¹ that isat most approximately 28% of the height of the reference peak. Inalternative embodiments, the absorbance between 1310 cm⁻¹ and 1285 cm⁻¹may be at most 25%, at most 20%, at most 15%, at most 10% or at most 5%of the peak of the reference peak.

Embodiments of the hydrocarbon feed may also exhibit specificcharacteristics under IR spectroscopy between the wavelengths orwavenumbers or wavenumbers of approximately 1135 cm⁻¹ and 1110 cm⁻¹. Forexample, the embodiments of the hydrocarbon feed may exhibit anabsorbance peak between the wavelengths or wavenumbers of 1135 cm⁻¹ and1110 cm⁻¹ that may be at most approximately 22% of the height of thereference peak. In alternative embodiments, the hydrocarbon feed 101 mayexhibit a peak that is at approximately most 20%, at most 15%, at most10% or at most 5% of the height of the reference peak.

Some embodiments of the hydrocarbon feed may also exhibit specificcharacteristics under IR spectroscopy between the wavelengths orwavenumbers of approximately 1040 cm⁻¹ and 1000 cm⁻¹. For example, theembodiments of the hydrocarbon feed may exhibit an absorbance peakbetween the wavelengths or wavenumbers of 1040 cm⁻¹ and 1000 cm⁻¹ thatmay be at most approximately 22% of the height of the reference peak. Inalternative embodiments, the hydrocarbon feed 101 may exhibit an IRabsorbance peak that is at most approximately 20%, at most 15%, at most10% or at most 5% of the height of the reference peak.

Referring again to FIG. 1 a, the heteroatom-containing hydrocarbon feed101 may be combined with an oxidant 104 and subjected to an oxidationreaction in a heteroatom oxidizer 102 or an oxidizer vessel.

Embodiments of the oxidation step may be carried out using at least oneoxidant, optionally in the presence of a catalyst. Suitable oxidants 104may include organic peroxides, hydroperoxides, hydrogen peroxide, O₂,air, O₃, peracetic acid, organic hydroperoxides may include benzylhydroperoxide, ethylbenzene hydroperoxide, tert-butyl hydroperoxide,cumyl hydroperoxide and mixtures thereof, other suitable oxidants mayinclude sodium hypochlorite, permanganate, biphasic hydrogen peroxidewith formic acid, nitrogen containing oxides (e.g. nitrous oxide), andmixtures thereof, with or without additional inert organic solvents.

In an alternative embodiment, the step of oxidation may further includean acid treatment including at least one immiscible acid. The immiscibleacid and oxidant treatment may remove a portion of the heteroatomcontaminants from the feed, wherein upon being oxidized by theimmiscible acid and oxidant, the heteroatoms may become soluble in theacid phase, and be subsequently removed via a heteroatom containingby-product stream. The immiscible acid used may be any acid which isinsoluble in the hydrocarbon oil phase. Suitable immiscible acids mayinclude, but are not limited to, carboxylic acids, sulfuric acid,hydrochloric acid, and mixtures thereof, with or without varying amountsof water as a diluent. Suitable carboxylic acids may include, but arenot limited to, formic acid, acetic acid, propionic acid, butyric acid,lactic acid, benzoic acid, and the like, and mixtures thereof, with orwithout varying amounts of water as a diluent.

In some embodiments, the oxidation reaction(s) may be carried out at atemperature of approximately 20° C. to about 120° C., at a pressure ofabout 0.1 atmospheres to about 10 atmospheres, with a contact time ofabout 2 minutes to about 180 minutes.

A catalyst may be used in the presence of the oxidant 104. A suitablecatalyst may include transition metals including but not limited toTi(IV), V(V), Mo(VI), W(VI), transition metal oxides, including ZnO,Al₂O₃, CuO, layered double hydroxides such as ZnAl₂O₄.x(ZnO)y(Al₂O₃),organometallic complexes such as Cu_(x)Zn_(1-x)Al₂O₄, zeolite, Na₂WO₄,transition metal aluminates, metal alkoxides, such as those representedby the formula M_(m)O_(m)(OR)_(n), and polymeric formulations thereof,where M is a transition metal such as, for example, titanium, rhenium,tungsten, copper, iron, zinc or other transition metals, R may be acarbon group having at least 3 carbon atoms, where at each occurrence Rmay individually be a substituted alkyl group containing at least one OHgroup, a substituted cycloalkyl group containing at least one OH group,a substituted cycloalkylalkyl group containing at least one OH group, asubstituted heterocyclyl group containing at least one OH group, or aheterocyclylalkyl containing at least one OH group. The subscripts m andn may each independently be integers between about 1 and about 8. Insome embodiments, R may be substituted with halogens such as F, Cl, Br,and I. For example, embodiments of the metal alkoxide catalyst mayinclude bis(glycerol)oxotitanium(IV)), wherein M is Ti, m is 1, n is 2,and R is a glycerol group. Other examples of metal alkoxides includebis(ethyleneglycol)oxotitanium (IV), bis(erythritol)oxotitanium (IV),bis(sorbitol)oxotitanium (IV).

The sulfoxidation catalyst may further be bound to a support surface.The support surface may include an organic polymer or an inorganicoxide. Suitable inorganic oxides include, but are not limited to, oxidesof elements of groups IB, II-A, II-B, III-A, III-B, IV-A, IV-B, V-A,V-B, VI-B, of the Periodic Table of the Elements. Examples of oxidesthat may be used as a support include copper oxides, silicon dioxide,aluminum oxide, and/or mixed oxides of copper, silicon and aluminum.Other suitable inorganic oxides which may be used alone or incombination with the abovementioned oxide supports may be, for example,MgO, ZrO₂, TiO₂, CaO and/or mixtures thereof. Other supports may includetalc.

The support materials used may have a specific surface area in the rangefrom 10 to 1000 m²/g, a pore volume in the range from 0.1 to 5 ml/g anda mean particle size of from 0.1 to 10 cm. Preference may be given tosupports having a specific surface area in the range from 0.5 to 500m²/g, a pore volume in the range from 0.5 to 3.5 ml/g and a meanparticle size in the range from 0.5 to 3 cm. Particular preference maybe given to supports having a specific surface area in the range from200 to 400 m²/g, and a pore volume in the range from 0.8 to 3.0 ml/g.

Referring still to FIG. 1 a, after subjecting a hydrocarbon stream tooxidation conditions in the heteroatom oxidizer vessel 102, anintermediate stream 106 may be generated. A hydrocarbon feed 101containing, for example sulfur-based heteroatom contaminants such asthiophenes, benzothiophenes, dibenzothiophenes and thioethers and othersmay be converted to a sulfone or sulfoxide rich intermediate stream 106.The intermediate hydrocarbon stream 106 may include oxidized heteroatomcontaining compounds and oxidant by-products. In some embodiments, theintermediate stream 106 may be subjected to distillation 107, forexample in a distillation column. During distillation 107, the oxidizedheteroatom containing compounds, may be separated from the oxidantby-products 109. The oxidant by-products may be recovered and recycled.As a result of the distillation 107, an oxidized hydrocarbonintermediate stream 111 may be formed including oxidized heteroatomcompounds such as sulfones and sulfoxide rich hydrocarbons. The oxidizedhydrocarbon intermediate stream 111 may also be referred to as asulfoxidized intermediate hydrocarbon product. The sulfone and sulfoxiderich, sulfoxidized intermediate hydrocarbon product 111 may be sent to areactor vessel 108 such as oil/caustic reactor vessel or promotedcaustic visbreaker 108. In some embodiments, the reactor vessel 108 maybe a sulfone management unit. Once inside the reactor vessel 108, theheteroatom rich stream 111, which may include sulfones and/orsulfoxides, may be subsequently reacted with a caustic treatmentsolution 110 in an alcoholysis reaction, under biphasic conditions toproduce a hydrocarbon product and sulfate salts. The caustic treatmentsolution may comprise caustic, a selectivity promoter and/or a causticselectivity promoter. FIG. 4 and FIG. 5 describe an embodiment of areaction mechanism for producing a hydrocarbon product 120 and a sulfatesalts 1040 under biphasic conditions 1000, 1010. In FIG. 4, the initialreaction may be a hydroxyl attack on the C—S bond of the sulfurcontaining compound present in the sulfone/sulfoxide rich oxidizedheteroatom containing stream, such as in a dibenzothiophene sulfonedepicted in FIG. 4. As a result of the hydroxyl attack, a hydrocarboncontaining a sulfonate group may form as a reaction intermediate.Without being bound to any particular theory, FIG. 5 provides onepossible explanation for the reaction mechanism.

Referring to FIG. 5, under the biphasic conditions of the oil/causticreactor vessel or promoted caustic visbreaker 108, one of the phases maybe a polar phase 1010 such as an organic alcohol, other selectivitypromoter or phase transfer agent. The other phase may be a non-polarphase 1000, which may include non-polar oil or hydrocarbon richmolecules. The boundary between the two phases is delineated by a phaseboundary 1020. The phase boundary may further be a liquid-solid phaseboundary. The intermediate sulfonate 1030, may align its polar sulfonategroup into the more preferable polar phase 1010 while the aromatichydrocarbon portion of the intermediate 1030 prefers the non-polar phase1000. Subsequently, a hydroxyl group or other nucleophile present in thepolar phase may perform a nucleophilic attack on the Sulfur of thesulfonate group. As a result of the nucleophilic attack, the sulfonateportion may form a sulfate 1040, a good leaving group. The sulfate 1040may remain in the polar phase 1010 and the hydrocarbon left behind mayremain in the non-polar phase of an intermediate stream 114. Theseparate phases allow for the hydrocarbon products 120 of the non-polarphase to be removed and separated from the heteroatom containingbyproducts 116 such as sulfates in separating vessel 115. In someinstances, undesired side reactions may occur. Referring to FIG. 2, itcan be seen that in situations wherein the sulfonate intermediate B maybe attacked by the hydroxyl nucleophile in the polar phase, the hydroxylmay perform a carbon selective attack on the carbon, forming the C—Obond instead of forming an S—O bond. In that instance, reaction (2) mayoccur resulting in phenolic hydrocarbon products and a sulfite, insteadof the formation of the biphenyl and sulfate depicted by reaction (3).Other oxide salts of sulfur may also be present (e.g. thiosulfate,thiosulfite, etc).

Referring again to FIG. 1 a, in some embodiments, the reactor vessel 108such as the oil/caustic reactor vessel or promoted caustic visbreakermay be heated to an elevated temperature between 100° C. and 500° C.with a pressure between 0 and 1000 psi. Suitable caustic compounds 110that may be used for the alcoholysis reaction may be compounds which mayexhibit basic properties. Caustic compounds may include inorganic oxideshaving group IA and IIA metals, inorganic hydroxides including group IAand IIA elements, alkali metal sulfides, alkali earth metal sulfides,mixtures and molten mixtures thereof. Non-limiting examples include, butare not limited to, Li₂O, Na₂O, K₂O, Rb₂O, Cs₂O, Fr₂O, BeO MgO, CaO,SrO, BaO, Na₂S, K₂S, LiOH, NaOH, KOH, RbOH, CsOH, FrOH, Be(OH)₂,Mg(OH)₂, Ca(OH)₂, Sr(OH)₂, Ba(OH)₂.

Caustic compounds may also include carbonate salts, such as alkali metalcarbonates and alkali earth metal carbonates including Na₂CO₃, K₂CO₃,CaCO₃, MgCO₃ and BaCO₃; phosphate salts, including alkali metalphosphates, such as sodium pyrophosphate, potassium pyrophosphate,sodium tripolyphosphate and potassium tripolyphosphate; and alkali earthmetal phosphates, such as calcium pyrophosphate, magnesiumpyrophosphate, barium pyrophosphate, calcium tripolyphosphate, magnesiumtripolyphosphate and barium tripolyphosphate; silicate salts, such as,alkali metal silicates, such as sodium silicate and potassium silicate,and alkali earth metal silicates, such as calcium silicate, magnesiumsilicate and barium silicate, organic alkali compounds expressed by thegeneral formula: R-E^(n)M^(m)Q^(m−1), where R is hydrogen or an organiccompound (which may be further substituted) including, but not limitedto, straight, branched and cyclic alkyl groups; straight, branched andcyclic alkenyl groups; and aromatic or polycyclic aromatic groups.Further substituents where R is an organic may include hydroxide groups,carbonyl groups, aldehyde groups, ether groups, carboxylic acid andcarboxylate groups, phenol or phenolate groups, alkoxide groups, aminegroups, imine groups, cyano groups, thiol or thiolate groups, thioethergroups, disulfide groups, sulfate groups, and phosphate groups. E^(n−)represents an atom with a negative charge (where n=−1, −2, −3, −4 etc.)such as oxygen, sulfur, selenium, tellurium, nitrogen, phosphorus, andcarbon; and M^(m) is any cation (m=+1, +2, +3, +4 etc.), such as a metalion, including, but not limited to, alkali metals, such as Li, Na, andK, alkali earth metals, such as Mg and Ca, and transition metals, suchas Zn, and Cu. When m>+1, Q may be the same as E^(n)-R or an atom with anegative charge such as Br−, Cl−, I, or an anionic group that supportsthe charge balance of the cation M^(m,) including but not limited to,hydroxide, cyanide, cyanate, and carboxylates.

In one embodiment of the present invention, the caustic may also be inthe molten phase. Molten phase caustics may include previously mentionedcaustics as well as eutectic mixtures thereof of two or more caustics.The eutectic mixtures of molten caustics may have a melting point lessthan 350° C., such as, for example, a 51 mole % NaOH/49 mole % KOHeutectic mixture which may melt at about 170° C.

Referring still to FIG. 1 a, a selectivity promoter may be introduced tothe reactor vessel as part of the caustic treatment solution 110. Theselectivity promoter may be any compound capable of being used in thealcoholysis reaction between the caustic and an oxidized heteroatomcontaining hydrocarbon to generate biphasic conditions that may promotethe formation of non-oxygenated hydrocarbon products 120 and sulfatesalts. In some embodiments, the selectivity promoter may also bereferred to as a phase transfer agent. Examples of heteroatom productsmay include non-oxygenated hydrocarbon products 120 including, but notlimited to, unsubstituted biphenyl compounds, and aromatic hydrocarbonsshown in FIG. 3. The alcoholysis reaction examples provided in FIG. 3,disclose multiple embodiments wherein a caustic mixture of NaOH and KOHmay be used with an Na₂S desulfonylation catalyst nucleophile andethylene glycol selectivity promoter. In the exemplary embodiment, thereaction may take place over 60 minutes at a pressure of 300 psi, at atemperature of approximately 275° C. In other embodiments, otherhydrocarbon distillates and fractions that are non-oxygenated, mayinclude, but not limited to, non-oxygenated crude oils or crude oilderived products such as gasolines, napthas, paraffins, olefins,asphaltenes/bitumens, diesel and gas oils. The non-oxygenated productsmay depend on the carbon groups of the heteroatom containing compoundspresent.

FIG. 2 further illustrates how the selectivity promoter and the biphasicconditions may improve the alcoholysis reaction to form more valuableproducts. Dibenzothiophene sulfone was chosen as an exemplary sulfurcompound because most of the challenging sulfur to treat in diesel fuelis in the form of substituted or unsubstituted dibenzothiophene.Equation (1) illustrates how hydroxide attacks the sulfur atom ofdibenzothiophene sulfone (A), forming biphenyl-2-sulfonate (B). Equation(2) illustrates how hydroxide may attack (B) at the carbon atom adjacentto the sulfur atom, forming biphenyl-2-ol (C) and sulfite salts (D).Compound C may ionize in basic media, and may dissolve in the aqueous ormolten salt layer. Equation (3) illustrates how hydroxide may attack thesulfur atom of (B) to form biphenyl (E) and sulfate salts (F). Equation(4) illustrates how, in the presence of a primary alcohol, including,but not limited to, methanol, methoxide ions generated in-situ mayattack the carbon atom, forming ether compounds, such as2-methoxybiphenyl (G). Equation (5) illustrates the reaction ofdibenzothiophene sulfone with alkoxides alone, not in the presence ofhydroxide to form biphenyl-2-methoxy-2′-sulfinate salt (H), which may besubstantially soluble in the polar caustic phase.

Using aqueous or molten caustic without the presently disclosedselectivity promoter may cause reaction (1) to occur, followedpredominantly by reaction (2). When a selectivity promoter disclosedherein is used, reaction (1) occurs, followed predominantly by reaction(3). Without being confined to any particular theory, it is believedthat the biphasic conditions may assist in promoting the selectivenucleophilic attack at the Sulfur. When the selectivity promoter (suchas an alcohol) disclosed herein is used, reaction (1) occurs, followedpredominantly by reaction (3) under biphasic conditions. It can be seenthat the hydrogen atoms that become attached to biphenyl may come fromhydroxide. When water is used in the regeneration of the caustic, theultimate source of the hydrogen atoms added to the biphenyl may bewater.

In some embodiments, the selectivity promoter may be referred to byother names including polar protic solvent, desulfonylation catalyst orphase transfer catalyst. Compounds suitable for promoting substantiallynon-oxygenated hydrocarbon reaction products may include organicalcohols, morpholine, dioxane, dimethylethanolamine,methyldiethanolamine, mono ethanolamine, diethanolamine,triethanolamine, crown ethers (18-crown-6, 15-crown-5), piperazine,choline hydroxide, benzyltrimethylammonium hydroxide, ethylene glycol,propylene glycol, glycerin, sugars, starches, cellulose, diethyleneglycol, triethylene glycol, polyethylene glycol, sulfides,hydrosulfides, polysulfides, hydroxide, cyanide, ammonia, anionicamides, halides, acetates, naphthenates, alkoxides, selenides,hydroselenides, tellurides, hydrotellurides, carboranes, phosphorousoxyanions, nitrogen oxyanions, aluminates, borates, carbonates,chromates, silicates, vanadates and titanates. Embodiments may includeintroducing an excess molar ratio of selectivity promoters to causticcations for increased conversion and selectivity.

Referring again to FIG. 1 a, in one embodiment the caustic treatmentsolution 110 may include at least one caustic and the at least oneselectivity promoter. The at least one caustic and at least oneselectivity promoters may be different components. In anotherembodiment, the at least one caustic and the at least one selectivitypromoter may be the same component. When the at least one caustic andthe at least one selectivity promoter are the same component they may bereferred to as a caustic selectivity promoter. Moreover, a suitablecaustic selectivity promoter may possess the properties of both the atleast one caustic and the at least one selectivity promoter. That is,combinations of caustics with selectivity promoters may react (in situor a priori) to form a caustic selectivity promoter which has theproperties of both a caustic and a selectivity promoter.

The molar ratio of caustic to selectivity promoter in the caustictreatment solution 110 may be in the range of from about 100:1 to about1:100. In some embodiments, the mole ratio of caustic to selectivitypromoter is in the range of from about 70:1-1:70, 50:1-1:50, 25:1-1:25,1:10, 10:1, 1-5-5:1, 3:1 to about 1:3 or from about 2:1 to about 1:2.

Generally, the molar ratio of caustic and selectivity promoter toheteroatom in the heteroatom-containing hydrocarbon feed oil 111 may bein the range of from about 100:1 to about 1:1. In some embodiments, themolar ratio of caustic and selectivity promoter to heteroatom in theheteroatom-containing hydrocarbon feed oil may be in the range of about10:1 to about 1:1, and in alternative embodiments, the molar ratio ofcaustic and selectivity promoter to heteroatom in theheteroatom-containing hydrocarbon feed oil may be from about 3:1 toabout 1:1.

Referring still to embodiment 100 in FIG. 1 a, the phases resulting fromthe contact of the caustic treatment solution 110 with the oxidizedheteroatom feed 111, may be separated into a light phase containing thehydrocarbon products 120 and a dense phase consisting of the causticcontaining byproducts. The intermediate 114 comprises a biphasic,caustic treated hydrocarbon intermediate stream that may be transferredto a separating vessel 115, such as a gravity settler in someembodiments to separate the hydrocarbon products 120 from the causticby-products 116. The hydrocarbon products 120 may be further washed,refined or utilized for gas, oil, fuel, lubricants or other hydrocarbonbased products and further treated using known refinery processes.Separation of the heavy caustic phase from the light oil phase may beperformed using gravity or other suitable separation methods. Thehydrocarbon product 120 may further be washed to remove traces ofby-product 116 with known methods including, but not limited to, solventextraction or by washing with water, centrifugation, distillation,vortex separation, and membrane separation and/or combinations thereof.Trace quantities of caustic and selectivity promoter may be removedusing electrostatic desalting and dewater techniques according to knownmethods by those skilled in the art.

Referring to alternative embodiment 200 in FIG. 1 b, the hydrocarbonfeed 211 may already be rich in sulfones or sulfoxides without having tooxidize the hydrocarbon feed or the hydrocarbon feed may be pre-oxidizedusing other known methods in the art. The hydrocarbon feed 211 may haveproperties similar to the sulfone or sulfoxide rich intermediate stream111 shown in FIG. 1 a. In this alternative embodiment, the steps ofoxidation 102 may not be needed. Instead, the sulfone or sulfoxide richoil may be sent directly from the source of the hydrocarbon feed 211into the oil/caustic reactor vessel 108. From the reactor vessel 108, acaustic treatment solution 110 may be provided into reactor 108 to forma biphasic mixture 114 of substantially non-oxygenated hydrocarbonproducts 120 and caustic byproducts 116. The hydrocarbon products 120may settle in the light phase, while the denser phase may containcaustic byproducts. The mixture 114 may be separated in a settler vessel115 or other vessel capable of separating the light phase from the densephase. Once separated, the hydrocarbon products 120 may be used directlyor transported, refined or fractionally distilled into one or moredistillate fractions. The distillate fractions may be further processedto produce hydrocarbon products such as gasoline, fuel oil, heating oil,lubricants or other hydrocarbon based products.

The hydrocarbon product 120 may be a liquid at standard temperature andpressure (STP). In some embodiments, the resulting hydrocarbon product120 may be a crude product wherein the crude product is a liquid mixtureat approximately 25° C. and 0.101 MPa. In some embodiments thehydrocarbon product 120 may have a TAN of at most 90% of the TAN of thehydrocarbon feed 101. In other embodiments, the TAN of the hydrocarbonproduct 120 may have a TAN of at most 80%, at most 60%, at most 50%, atmost 40%, at most 30% at most 20% or at most 10% of the hydrocarbonfeed. In certain embodiments, the hydrocarbon products may have a TAN ofat most 1, while in other embodiments, the TAN may range from at most0.5, at most 0.3, at most 0.2 or at most 0.1 mg of KOH equivalent pergram of oil. Embodiments of the hydrocarbon product 120 may have a TANthat ranges. For example, the hydrocarbon may have a TAN ranging from0.001 to 0.5, 0.004 to 0.4 or from 0.01 to 0.2. In certain embodiments,the hydrocarbon products may have a TAN measuring less than 0.5 mg KOHequivalent per gram of the hydrocarbon product.

In some embodiments, the hydrocarbon product 120 may include a contentof trace metallic heteroatoms such as Ni, V and Fe wherein the contentof the metallic heteroatoms may be at most 90% of the metallicheteroatom content of the hydrocarbon feed. In other embodiments, themetallic heteroatom content may be at most 80%, at most 70%, at most60%, at most 50%, at most 30%, at most 10%, or at most 5% of themetallic heteroatom content of the hydrocarbon feed 101. In certainembodiments, the hydrocarbon product 120 may have a metallic heteroatomcontent per gram of hydrocarbon product ranging from 1×10⁻⁷ g to 5×10⁻⁴g or approximately 0.1 ppm to approximately 50 ppm.

In some embodiments, the crude product may have a total content ofmetals in metal salts of organic acids of at most 90% of the totalcontent of metals in metal salts in organic acids of the hydrocarbonfeed. In other embodiments, the content of metals in metal salts oforganic acids may range from at most 50% to at most 5% of the contentfound in the hydrocarbon feed. Organic acids that may form metal saltsmay include carboxylic acids such as napthenic acids, phenanthrenicacids and benzoic acid. Other organic acids that might form metal saltsmay include thiols, imides, sulfonic acids and sulfonates. Metals thatmay form metal salts in organic acids may include alkali metals, alkaliearth metals, and transition metals from groups 3-12 of the periodictable including Ti, Zr, Zn, Cu, Ni and cadmium. Other metals that mayform metal salts may include metalloids (also called semi-metals) foundin group 13-16 of the periodic table include for example aluminum,arsenic, boron and selenium. In one or more embodiments, the hydrocarbonproduct 120 may have a total content of metals in metal salts of organicacids, in the range from 0.0000001 g to 0.0005 g per gram of hydrocarbonproduct.

In certain embodiments, the API gravity of the hydrocarbon product 120produced from the caustic treatment may be between 10 and 30. In otherembodiments, the API gravity of the hydrocarbon product may be increasedby at least 3 units over the API gravity of the hydrocarbon feed 101, atleast 10 units over the API gravity of the hydrocarbon feed or at least15 units over the API gravity of the hydrocarbon feed 101. In yetanother embodiment, the API gravity of the hydrocarbon product may be atleast 12, at least 15, at least 20 or at least 25.

Embodiments of the hydrocarbon products 120 may have a viscosity lessthan the viscosity of the hydrocarbon feed. For example, in someembodiments, the viscosity may be at most 90% of the viscosity of thehydrocarbon feed 101. In other embodiments, the viscosity of thehydrocarbon product may be at most 80% or at most 70% of the hydrocarbonfeed. Embodiments of the hydrocarbon product 120 may also have a totalheteroatom content that is at most 90% of the total heteroatom contentof the hydrocarbon feed. In certain embodiments, the hydrocarbonproducts may contain at most 50%, at most 10% or at most 5% of theheteroatom content of the hydrocarbon feed 101. In some embodiments, theviscosity of the hydrocarbon composition may be measured by a stabingerviscometer.

Embodiments of the hydrocarbon product 120 may have a sulfur contentthat may be at most 95% of the hydrocarbon feed. In other embodiments,the sulfur content may be at most 50%, at most 10% or at most 5% of thesulfur content of the hydrocarbon feed. In one or more embodiments, thesulfur content of the hydrocarbon product 120 may be less thanapproximately 4.0 wt % of the hydrocarbon product. The wt % of thesulfur content may be measured by ASTM D7049 or equivalent methods.

In some embodiments the hydrocarbon products may contain per gram ofhydrocarbon product, at least 0.0005 gram of sulfur or at least 0.001gram of sulfur. The sulfur content of the hydrocarbon composition may bedetermined in accordance with ASTM Method D4294. A substantial portionof the sulfur in the hydrocarbon composition may be contained inhydrocarbons having a carbon number of 17 or less, where at least 40 Wt.%, or at least 50 Wt. %, or at least 60 Wt. %, or at least 70 Wt. % ofthe sulfur may be contained in hydrocarbons having a carbon number of 17or less, Where at least 60 Wt. %, or at least 70 Wt. %, or at least 75Wt. % of the sulfur contained in hydrocarbons having a carbon number of17 or less may be contained in benzothiophenic compounds. The amount ofsulfur in hydrocarbons having a carbon number of 17 or less and theamount of sulfur in benzothiophenic compounds in the hydrocarboncomposition relative to all sulfur containing compounds in thehydrocarbon composition may be determined by two dimensional gaschromatography (GCxGC-SCD).

In some embodiments, the total nitrogen content of the hydrocarbonproduct 120 may be at most 90% of the hydrocarbon feed. In otherembodiments, the nitrogen content may be at most 50%, at most 10% or atmost 5% of the nitrogen content of the hydrocarbon feed 101. In one ormore embodiments, the nitrogen content of the hydrocarbon product 120may be less than approximately 0.2 wt % of the hydrocarbon product. Thewt % of nitrogen content may be measured by ASTM D5291 or equivalentmethods. In some embodiments, the nitrogen content may contain, per gramof hydrocarbon product, at least 0.0005 gram or at least 0.001 gram ofnitrogen as determined in accordance With ASTM Method D5762. Thehydrocarbon product may have a relatively low ratio of basic nitrogencompounds to other nitrogen containing compounds. In some embodiments,at least 30 Wt. % of the nitrogen is contained in hydrocarbon compoundshaving a carbon number of 17 or less, and at least 35 Wt. % or at least40 Wt. % of the nitrogen may be contained in hydrocarbon compoundshaving a carbon number of 17 or less.

In some embodiments, the oxygen content of the hydrocarbon product maybe at most 90% of the hydrocarbon feed. In other embodiments, the oxygencontent may be at most 50%, at most 30%, at most 10% or at most 5% ofthe oxygen content of the hydrocarbon feed. In certain embodiments, theoxygen content may be less than approximately 1.2 wt % of thehydrocarbon product.

In some embodiments, the hydrocarbon product may include fromapproximately 0.05-0.15 grams of hydrogen per gram of hydrocarbonproduct 120. The hydrocarbon product may include in its molecularstructure 0.8 to 0.9 grams of carbon per gram of hydrocarbon product.The hydrocarbon product may have a ratio of atomic carbon to atomichydrogen (C/H) within 70-130% of the hydrocarbon feed. In an exemplaryembodiment, the C/H ratio of the hydrocarbon product may be >90% of thehydrocarbon feed. Embodiments of a hydrocarbon product may have ahydrogen to carbon ratio of the hydrocarbon less than or equal to 1.7:1in some embodiments. In other embodiments, the H/C ratio may be betweenapproximately 0.01:1 to 0.09:1, between 0.1:1 to 0.49:1, between 0.50:1to 1:1 and/or between 1:1 to 1.7:1. Accordingly, in some embodiments,the H/C ratio may be less than 1:100, less than 1:75, less than 1:50,less than 1:30, less than 1:20 or less than 1:10.

In some embodiments, the hydrocarbon product 120 may be amenable toadditional refinery operations and treatments, including but not limitedto distillation, hydrotreating, alkylation, hydrocracking, fluidcatalytic cracking, coking, and visbreaking

In some embodiments, the hydrocarbon products may be hydro-treated toadjust the H/C or C/H ratio of the hydrocarbon products and/or decreasethe sulfur content of the hydrocarbon products. A hydrocarbon productwith a C/H ratio within 10-30% of the hydrocarbon feed may indicate thatthe uptake or consumption of hydrogen was relatively small and/or thatthe hydrogen was produced in situ. In some embodiments, the hydrocarbonproduct with a low C/H ratio may be sent to a refinery for furtherprocessing wherein the refinery may modify the C/H ratio by increasingthe hydrogen content as needed in the formation of the refined product.In such an embodiment, the oil producers may save money by avoiding theaddition of costly hydrogen processing, while still being able toeconomically transport the oxidized hydrocarbon products.

Referring to FIG. 6 a-6 f, which depicts various boiling pointdistributions for hydrocarbon feeds such as crude bitumen, sulfoxidizedintermediates 111 of the hydrocarbon feed and the boiling point ofdistributions of various hydrocarbon products based on the amount ofheteroatom removal that has occurred. For example, the hydrocarbonproducts 120 may contain VGO hydrocarbons, distillate hydrocarbons(kerosene and diesel), naphtha hydrocarbons and residual hydrocarbons(asphalt and bitumen). The hydrocarbon composition may contain, per gramof hydrocarbon composition, at least 0.1 grams of hydrocarbons having aboiling point from the initial boiling point (IBP) of the hydrocarboncomposition up to 204° C. (400° F.). The hydrocarbon composition mayalso contain, per gram of hydrocarbon composition, at least 0.15 gramsof hydrocarbons having a boiling point from 204° C. up to 260° C. Thehydrocarbon composition may also contain, per gram of hydrocarboncomposition, at least 0.3 grams, or at least 0.35 grams of hydrocarbonshaving a boiling point of from 260° C. up to 343° C. The hydrocarboncomposition may also contain, per gram of hydrocarbon composition, atleast 0.35 grams, or at least 0.4 grams, or at least 0.45 grams ofhydrocarbons having a boiling point of from 343° C. up to 538° C. Therelative amounts of hydrocarbons within each boiling range and theboiling range distribution of the hydrocarbons may be determined inaccordance with ASTM Method D5307 or an equivalent method thereof.

Referring still to FIG. 6 a-6 f, the hydrocarbon product 120 may includehydrocarbons within one or more ranges of boiling points. In someembodiments, the hydrocarbon product may include at least 0.1 g ofhydrocarbons per gram of hydrocarbon product having a boiling rangedistribution between the initial boiling point and 739° C. In otherembodiments, the hydrocarbon product may have approximately at least 0.2g, at least 0.3 g, at least 0.4 g, at least 0.5 g, at least 0.8 g, atleast 0.9 g of hydrocarbons per gram of hydrocarbon product having aboiling range distribution between the IBP and the 739° C.

In some embodiments, the hydrocarbon product may include at least 0.05grams of hydrocarbons per gram of hydrocarbon product 120 having aboiling range distribution from the initial boiling point of thehydrocarbon product to 67° C. The initial boiling point may be thetemperature wherein a hydrocarbon or mixture of hydrocarbons firstbegins to boil. The IBP may vary depending on the composition ofhydrocarbons present. For example, a hydrocarbon product including ahigh gasoline hydrocarbon content having short chain hydrocarbonsbetween 4-12 carbons per molecule will begin to boil at a much lowertemperature than a mixture of hydrocarbons lacking gasoline. Forexample, a hydrocarbon product with a high concentration of gasolinesmay have an initial boiling point of less than 70° C., whereas ahydrocarbon product including a higher concentration of gas oil ordiesel and a lower concentration of gasolines may have a higher initialboiling point around 120-150° C. In an embodiment including fewgasolines and a lower concentration of gas oil or diesel, and insteadhaving a higher concentration of lubricating oils, the hydrocarbonproduct may have an IBP of approximately 150-300° C. In comparison, ahydrocarbon product having a high concentration of fuel oil fractionsbut still having a fair amount of naphtha and gasoline may still have alower IBP because the naphtha and gasoline may begin to boil attemperature between 40-200° C. In a hydrocarbon product that ispredominantly lubricating oil, heavy gas and residual products, thehydrocarbon mixture may have a much higher IBP than the previousexamples, for instance between 275° C.-450° C.

In some embodiments, the hydrocarbon product 120 may include 0.01 to0.25 grams of hydrocarbon per gram of hydrocarbon product having aboiling range distribution between the IBP of the hydrocarbon productsand 204° C. In another embodiment, the hydrocarbon product may includeat least 0.1 gram of hydrocarbons per gram of hydrocarbon product havinga boiling range distribution from the IBP to 253° C. In otherembodiments, the hydrocarbon product may include at least 0.4 g ofhydrocarbons per gram of hydrocarbon product having a boiling rangedistribution between IBP of the hydrocarbon product to approximately538° C.

Additional embodiments of the hydrocarbon product 120 may include atleast 0.05 g of hydrocarbons per gram of hydrocarbon products having aboiling point distribution between 204° C. and 260° C. Embodiments ofthe hydrocarbon product 120 may further include at least 0.1 grams ofhydrocarbons per gram of hydrocarbon product 120 having a boiling pointdistribution between 260° C. to 343° C. Embodiments of the hydrocarbonproducts may also include at least 0.2 grams of hydrocarbons per gram ofthe hydrocarbon product 120 with a boiling range distribution between343° C. and 510° C. In certain embodiments, of the hydrocarbon products,the hydrocarbon products may contain at least 0.75 grams of hydrocarbonsper gram of hydrocarbon product having a boiling range distribution fromthe IBP of the hydrocarbon products 120 up to 739° C. In otherembodiments, the hydrocarbon products 120 may include at most 0.3 gramsof hydrocarbons per gram of hydrocarbon products having a boiling rangedistribution greater than 738° C.

In some embodiments, the hydrocarbon products 120 may have at least 0.05g of gasolines per gram of hydrocarbon product. The gasoline fractionmay have a boiling range distribution between the IBP of the hydrocarbonproduct and approximately 67° C. In other embodiments, the hydrocarbonproduct may have at most 0.6 grams of gasolines per gram of hydrocarbonproduct.

In some embodiments, the hydrocarbon product may have less than 0.001 gof olefinic hydrocarbons per gram of hydrocarbon product. In someembodiments, the hydrocarbon product may have at least 0.001 g ofolefinic hydrocarbons per gram of the hydrocarbon product. In one ormore embodiments, the hydrocarbon product may contain less than 0.02 gof olefins per gram hydrocarbon product. The amount of olefinichydrocarbons measured per gram of the hydrocarbon product may bemeasured using the Canadian Crude Quality Technical Association(CCQTA)—Olefins in Crude Oil by ¹H-NMR method. The olefinic hydrocarbonfractions may have a boiling range distribution between the IBP of thehydrocarbon product and 253° C. Non-limiting examples of olefins mayinclude for example, styrene, 1-hexene, cyclohexene, limonene, andtrans-stilbene.

In some embodiments, the hydrocarbon product may have between 0.01 g and0.30 g of gasolines, naphtha, and/or paraffin, per gram of hydrocarbonproduct. The gasolines, naphtha and/or paraffin fractions may have aboiling point range distribution between the IBP and approximately 204°C.

In one or more embodiments, the hydrocarbon product may contain at least0.05 g of diesel oil per gram hydrocarbon products. In otherembodiments, the hydrocarbon product may contain at most 0.8 g of dieseloil per gram of hydrocarbon product. The diesel oil fraction may haveboiling range distribution between approximately 204° C. and 260° C.

In some embodiments, the hydrocarbon products may contain at least 0.1 gof lubricating oils per gram of hydrocarbon products. In otherembodiments, the lubricating oils may be at most 0.8 g per gram ofhydrocarbon product. The lubricating oil fraction may have a boilingrange distribution between approximately 260° C. and 343° C.

Embodiments of the hydrocarbon products may contain at least 0.2 g offuel oils, greases, waxes and/or some bitumens per gram hydrocarbonproduct. In other embodiments, the hydrocarbon product may contain atmost 0.8 g of fuel oils, greases, waxes and/or some bitumens per gramhydrocarbon product. The fuel oils, greases, waxes and/or some bitumensmay have a boiling range distribution between approximately 343° C. and510° C.

Embodiments of the hydrocarbon products may contain at most 0.3 g ofbitumen per gram of hydrocarbon product wherein the bitumen has aboiling point range distribution greater than 738° C.

The hydrocarbon products 120 of the present invention may containsignificant quantities of aromatic hydrocarbon compounds. Thehydrocarbon product may contain, per gram of hydrocarbon product, atleast 0.3 gram, or at least 0.35 gram, or at least 0.4 gram, or at least0.45 gram, or at least 0.5 gram of aromatic hydrocarbon compounds.

In some embodiments, the hydrocarbon product may have a distillatecontent between 50-150% of the distillate content of the hydrocarbonfeed. The distillate content of the distillate hydrocarbons per gram ofhydrocarbon product may be in a range from 0.00001-0.8 g. In certainembodiments, the hydrocarbon product may have VGO content of 50-150% ofthe VGO content of the hydrocarbon feed. In some embodiments, the VGOcontent may range from 0.0001-0.8 g per gram of hydrocarbon product.

Embodiments of the hydrocarbon product may have a residue content of atmost 90% of the hydrocarbon feed. In other embodiments, the residuecontent may be at most 80%, at most 50%, at most 30%, at most 20%, atmost 10% or at most 3% of the residue content of the hydrocarbon feed.In certain embodiments, the hydrocarbon products may have a residuecontent between 70-130% of the residue content of the hydrocarbon feed.

Embodiments of the hydrocarbon product may have a total C₅ and C₇asphaltene content of at most 90% of the total C₅ and C₇ asphaltenecontent of the hydrocarbon feed. In other embodiments, the asphaltenecontent may be at most 50%, at most 30% or at most 10% of thehydrocarbon feed. In certain embodiments, the hydrocarbon feed may havea total C₅ and C₇ asphaltene content of at least 0.01 g per gram ofhydrocarbon product. In other embodiments, the asphaltene content may beat most 0.5 g per gram of hydrocarbon product. In some embodiments, theasphalt content of the hydrocarbon product may be the content of C₅and/or the content of C₇ asphaltene. The asphalt content may be measuredusing ASTM D3279-2 or an equivalent method thereof. The asphalt contentmay be the measurement of the grams of asphaltene insoluble n-heptaneper gram of hydrocarbon product containing asphalt. In one embodiment,the asphalt content may be at least 0.3 g of asphaltene may be insolublein n-heptane, per gram of hydrocarbon product. A hydrocarbon productcontaining asphalt or asphaltenes may have a hydrogen to carbon ratio ofless than 1.5:1 in some embodiments. The H/C ratio of hydrogen to carbonmay be determined by ASTM D5291 or equivalent method. In someembodiments, the H/C ratio may be between approximately 0.01:1 to0.09:1, between 0.1:1 to 0.49:1, between 0.50:1 to 1:1 and/or between1:1 to 1.5:1. Accordingly, in other embodiments, the H/C ratio may beless than 1:100, less than 1:75, less than 1:50, less than 1:30, lessthan 1:20 or less than 1:10.

A hydrocarbon product containing asphalt or asphaltenes may be theproduct of a crude asphalt hydrocarbon feed. In embodiments where acrude asphalt hydrocarbon feed is used for hydrocarbon feed 101, thetotal acid number of the asphalt hydrocarbon product 120 may be lessthan the total acid number of the crude asphalt hydrocarbon feed. Insome embodiments, the TAN of asphalt hydrocarbon products may be between5 to 90% of the TAN of the asphalt hydrocarbon feed. Embodiments of anasphalt hydrocarbon product may have a TAN less than 0.5 mg KOH per gramof asphalt containing hydrocarbon product.

A hydrocarbon product containing asphalt or derived from a crude asphalthydrocarbon feed subjected to oxidative desulfurization treatment mayhave a viscosity of hydrocarbon product that is less than the viscosityof the hydrocarbon feed. For instance, in some embodiments, theviscosity of the asphalt containing hydrocarbon product may have aviscosity less than the hydrocarbon feed measured at 15° C., 80° C.,100° C., 120° C. using ASTM D7042 to measure the viscosity. In otherembodiments, ASTM D7042 methods may be used to measure the density ofthe hydrocarbon product and hydrocarbon feeds containing asphalts andcrude asphalts. The density of the hydrocarbon feed may be 1.05grams/cubic centimeter (g/cc) or greater when measured at 15° C. Inother embodiments, the density of the hydrocarbon product may bemeasured at intervals above 15° C., such as 80° C., 100° C. and 120° C.then extrapolated back to 15° C. to determine that the density of thehydrocarbon product is greater than 1.05 g/cc.

In some embodiments, as a result from removing heteroatoms from thehydrocarbon feed, the light oil phase containing the hydrocarbonproducts 120, may have a lower density and viscosity than the untreated,contaminated feed. The heavy caustic phase density may be in the rangefrom about 1.0 to about 3.0 g/cc and the light product oil phase mayhave density generally in the range of from about 0.7 to about 1.1 g/ccas measured at 15° C.

In some embodiments, the composition of the crude asphalt hydrocarbonproduct may have some residual or remaining metals after oxidativedesulfurization. The metal content of the hydrocarbon product may beless than the crude asphalt hydrocarbon feed. In some embodiments, thehydrocarbon product may have a total metal content that is less than 90%of the metal content of the hydrocarbon feed. In other embodiments, thehydrocarbon product may be less than 50%, less than 20% or less than 10%of the metal content of the hydrocarbon feed. The product may be furthertreated by other well-known refinery operations including, but notlimited to: hydrotreating, hydrocracking, fluidized catalytic cracking,coking, distillation, etc.

In some embodiments, the hydrocarbon feed 101, hydrocarbon products 120and the intermediate products 111 may be characterized using infrared(IR) spectroscopy to identify the characteristics and properties of thehydrocarbons. The IR spectra may be used to measure the absorbance (A)at each wavelength or wavenumber and then the peaks may be plotted alongthe spectrum, wherein the location along the spectrum may signify thefunctional class (such as sulfoxide or sulfone) and the height or areaof the peak may be proportional to the amount (for example weight %) ofthe functional class present. A non-limiting list of examples offunctional classes are provided in Table 1 and Table 2 below.

The hydrocarbon feed, hydrocarbon products and intermediate products maybe measured by any known infrared spectroscopy techniques. For example,each of the hydrocarbons may be measured using attenuated totalreflectance Fourier Transform Infrared Spectroscopy. Embodimentsmeasuring the content of the hydrocarbon feed 101, the sulfoxidizedintermediate stream 111 and the hydrocarbon product may be measured“neat” in some embodiments (without the addition of solvents oradditives).

The IR spectra provided in FIG. 7 a to FIG. 7 e demonstrate an exampleof using IR to characterize, compare and contrast the compositions andcontent of the hydrocarbon feed 101, hydrocarbon product 120 andintermediate stream 111. In some embodiments, the infrared spectroscopypeaks or areas of interest in classifying the signature compositions ofthe intermediate stream and the hydrocarbon products may be those peaksor areas corresponding to sulfone and sulfoxide functional groups. Table1 provides an example of typical infrared absorption frequencies andsome sample characteristics describing the vibrations, range andintensity of the bands. Table 2 below provides example absorption rangesfor IR spectroscopy for various functional classes including classes ofcompositions that may be present in hydrocarbon feeds, sulfoxidizedintermediate streams and the hydrocarbon product such as sulfones,sulfoxides and sulfates.

TABLE 1 Stretching Vibrations Bending Vibrations Functional Range RangeClass (cm⁻¹) Intensity Assignment (cm⁻¹) Intensity Assignment Alkanes2850-3000 str CH₃, CH₂ & CH 1350-1470 med CH₂ & CH₃ 2 or 3 bands1370-1390 med deformation 720-725 wk CH₃ deformation CH₂ rocking Alkenes3020-3100 med ═C—H & ═CH₂ 880-995 str ═C—H & ═CH₂ 1630-1680 var (usuallysharp) 780-850 med (out-of-plane 1900-2000 str C═C (symmetry 675-730 medbending) reduces cis-RCH═CHR intensity) C═C asymmetric stretch Alkynes3300 str C—H (usually 600-700 str C—H 2100-2250 var sharp) deformationC≡C (symmetry reduces intensity) Arenes 3030 var C—H (may be 690-900str-med C—H bending & 1600 & 1500 med-wk several bands) ring C═C (inring) (2 puckering bands) (3 if conjugated) Alcohols & 3580-3650 var O—H(free), 1330-1430 med O—H bending Phenols 3200-3550 str usually sharp650-770 var-wk (in-plane)  970-1250 str O—H (H- O—H bend bonded),(out-of- usually broad plane) C—O

TABLE 2 Functional Class Characteristic Absorptions Sulfur Functions S—Hthiols 2550-2600 cm⁻¹ (wk & shp) S—OR esters  700-900 (str) S—Sdisulfide  500-540 (wk) C═S thiocarbonyl 1050-1200 (str) S═O sulfoxide1030-1060 (str) sulfone 1325 ± 25 (as) & 1140 ± 20 (s) (both str)sulfonic acid 1345 (str) sulfonyl chloride 1365 ± 5 (as) & 1180 ± 10 (s)(both str) sulfate 1350-1450 (str) Phosphorous Functions P—H phosphine2280-2440 cm⁻¹ (med & shp)  950-1250 (wk) P—H bending (O═)PO—Hphosphonic acid 2550-2700 (med) P—OR esters  900-1050 (str) P═Ophosphine oxide 1100-1200 (str) phosphonate 1230-1260 (str) phosphate1100-1200 (str) phosphoramide 1200-1275 (str) Silicon Functions Si—Hsilane 2100-2360 cm⁻¹ (str) Si—OR 1000-11000 (str & brd) Si—CH₃ 1250 ±10 (str & shp) Oxidized Nitrogen Functions ═NOH oxime O—H (stretch)3550-3600 cm⁻¹ (str) C═N 1665 ± 15 N—O 9454 ± 15 N—O amine oxidealiphatic  960 ± 20 aromatic 1250 ± 50 N═O nitroso 1550 ± 50 (str) nitro1530 ± 20 (as) & 1350 ± 30 (s)

Referring to FIGS. 7 a to 7 e as an example of an IR spectra, aninfrared spectroscopy reference peak may be established betweenapproximately 1445 cm⁻¹ and 1465 cm⁻¹ for the hydrocarbon product 120,intermediate product 111 and the hydrocarbon feed 101. In someembodiments, the peak height or area of the reference peak may be atapproximately 1455 cm⁻¹. In the embodiments depicted in FIG. 7 a to FIG.7 e, the height or area of the reference peak may be normalized so thatthe peak height or area of the reference peak may be approximately 1.0absorbance (A). In an alternative embodiment, the reference peak may bemeasured by absolute absorbance rather than normalizing the curve.

As shown in FIG. 7 b and FIG. 7 d, intermediate products 111 may becharacterized by the presence of infrared spectroscopy peaks identifiedby one or more peaks recorded using IR spectroscopy. The peaks may bereferred to as a first, second, third, fourth or fifth peak, etc.,however name of the peak denotes the order in which the peak isdiscussed. The location and identifying nature of the peak may be basedon the wavelength or wavenumber where the peak may be located during IRspectroscopy, not the designation of the peak as the first, second orthird, etc. For example, a peak that may be described as a first peak inone embodiment because it resides at a lower wavenumber, may also bereferred to as a second peak, or a third peak in another embodiment whenthe peak appears subsequent to another peak. Likewise, a peak that maybe present in an IR spec as a “second peak” in a first embodiment may bereferred to as a first peak in a second embodiment wherein the “firstpeak” of the first embodiment is not present in the second embodiment.

A first peak that may characterize the contents of the intermediateproducts 111 may be present on the IR spectrum between the wavelengthsor wavenumbers of approximately 1310 cm⁻¹ to 1285 cm⁻¹. This first peakmay have a height or area that is at least approximately 28% of theheight or area of the reference peak. In some embodiments, the firstpeak may have a height or area that is approximately at least 30%, atleast 35%, at least 40%, at least 50%, at least 70%, at least 85%, atleast 100% or greater than 100% of the height or area of the referencepeak.

Embodiments of the intermediate products 111 may also be classifiedusing IR spectroscopy by the presence of another peak. This second peakmay appear on an IR spectroscopy readout at a wavelength or wavenumberbetween approximately 1135 cm⁻¹ and 1110 cm⁻¹. The peak height or areaof this second peak may be present at a wavelength or wavenumber ofapproximately 1125 cm⁻¹. Embodiments of the intermediate product 111,may exhibit this second peak with height or area that is approximatelyat least 22% of the height or area of the reference peak. In someembodiments, this second peak may have a height or area that is at least25%, at least 30%, at least 40%, at least 50%, at least 70%, at least85%, at least 100% or greater than 100% of the height or area of thereference peak.

In some embodiments of the intermediate products 111, the intermediateproducts may be characterized by the presence of yet a third peakidentified using IR spectroscopy. This third peak may appear on an IRspectroscopy readout at a wavelength or wave number betweenapproximately 1040 cm⁻¹ and 1000 cm⁻¹. The peak height or area of thethird peak may be present at a wavelength or wavenumber of approximately1031 cm⁻¹. Embodiments of the intermediate product 111, may exhibit athird peak having a height or area that is approximately at least 22% ofthe height or area of the reference peak. In some embodiments, thesecond peak may have a height or area that is at least 25%, at least30%, at least 40%, at least 50%, at least 70%, at least 85%, at least100% or greater than 100% of the height or area of the reference peak.

Embodiments of the hydrocarbon product 120 may also be characterized byIR spectroscopy in a manner similar to the intermediate products 111.For example, the hydrocarbon products may be characterized by thepresence of peaks identified by one or more peaks recorded using IRspectroscopy. For example, in one embodiment, a first peak that maycharacterize the contents of the hydrocarbon products 120 may be presenton the IR spectrum between the wavelengths or wavenumbers ofapproximately 1310 cm⁻¹ to 1285 cm⁻¹. This first peak may have a heightor area that is at least approximately 28% of the height or area of thereference peak. In some embodiments, the first peak may have a height orarea that is approximately at least 30%, at least 35%, at least 40%, atleast 50%, at least 70%, at least 85%, at least 100% or greater than100% of the height or area of the reference peak.

Embodiments of the hydrocarbon product may also be classified using IRspectroscopy by the presence of other peaks. A second peak that mayappear on an IR spectroscopy readout may be at a wavelength orwavenumber between approximately 1135 cm⁻¹ and 1110 cm⁻¹. The peakheight or area of this second peak may be present at a wavelength orwave number of approximately 1125 cm⁻¹. Embodiments of the hydrocarbonproducts 120, may exhibit a second peak with height or area that isapproximately at least 22% of the height or area of the reference peak.In some embodiments, the second peak may vary in height or area, forexample, the height or area of the second peak may be at least 25%, atleast 30%, at least 40%, at least 50%, at least 70%, at least 85%, atleast 100% or greater than 100% of the height or area of the referencepeak.

In some embodiments of the hydrocarbon products 120, the hydrocarbonproducts may be characterized by the presence of a third signature peakidentified using IR spectroscopy. The third peak may appear on an IRspectroscopy readout at a wavelength or wavenumber between approximately1040 cm⁻¹ and 1000 cm⁻¹. The peak height or area of the third peak maybe present at a wavelength or wavenumber of approximately 1031 cm⁻¹.Embodiments of the hydrocarbon product 120, may exhibit a third peakhaving a height or area that is approximately at least 22% of the heightor area of the reference peak. In some embodiments, the second peak mayhave a height or area that is at least 25%, at least 30%, at least 40%,at least 50%, at least 70%, at least 85%, at least 100% or greater than100% of the height or area of the reference peak.

In the embodiments of the intermediate product 111 and the hydrocarbonproduct 120, having a reference peak, a first peak, a second peak or athird peak, the wavelength or wavenumber classifying the location of thepeaks may vary between +/−10% of the value of the upper and lower boundsof the peak's range described herein. Distillates derived fromintermediate product 111 or hydrocarbon product 120 having a referencepeak and a plurality of peaks such as a first peak, a second peak or athird peak, the peak heights or areas in relation to the reference peakmay vary between +/−60% of those described herein. The followingnon-limiting examples illustrate certain aspects of the presentinvention:

EXAMPLE 1

Preparation of Catalyst

Bis(glycerol)oxo titanium(IV) is prepared according to the method ofU.S. Pat. No. 8,394,261 B2 which is hereby incorporated by reference.Titanium oxychloride (2 kilograms (kg), Millenium Chemicals) is dilutedwith de-ionized water (2 kg) and then added to a 20 liter (1) roundbottom flask containing glycerine (2 kg). The mixture is allowed to stiruntil a straw color is attained. The 20 liter round bottom flask is thenheated to 50° C. under vacuum (−25 inches Hg) in a rotary evaporator toremove excess water and hydrochloric acid. When no further liquidcondensate is noted, the flask is recharged with water (0.65 l) androtary evaporated to further remove excess water and hydrochloric acid.This is repeated two additional times. After the final evaporation, theviscous, straw colored liquid is weighed (2.64 kg) and diluted withmethoxypropanol (0.85 kg) to reduce the viscosity. This is thenneutralized with triethylamine (3.3 kg, 33% weight/weight in ethanol).The combined neutralized solution is then chilled for several hoursproducing rod-like needles of triethylamine hydrochloride. Thecrystalline triethylamine hydrochloride is removed by vacuum filtration.The filtrate is added slowly to acetone (70 L) causing the product toprecipitate as a white solid. The acetone is then decanted and anoff-white solid residue is obtained. The off-white solid residue is thenwashed vigorously with hexanes (20 L) to afford a fine white powder. Thepowder is collected by filtration (>63% yield based upon Ti). % TiCalculated: 16.98. Analysis: 16.7; mp DSC (dec) 273° C.; ESI-MS(positive mode) 245 amu; ¹H-NMR (DMSO-d6) 4.25 (br s, 4H), 3.45 (m, 2H),3.38 (m, 4H), 3.31 (m, 4H).

EXAMPLE 2

General Method for Adsorption of Catalyst onto Support

A 2% by weight solution of the catalyst from example 1 is prepared bymixing with methanol. The solution is added to a silica support untilthe solids are fully immersed at ambient temperature. The solids areallowed to soak for approximately 30 minutes, or until all air isdisplaced. The liquid is decanted from the solids and the solids aredried in vacuo (50° C.) until the weight of the solids no longerchanges. A 40% solution of t-butyl hydroperoxide in xylene is added tothe dried catalyst-coated support until the solids are fully immersed.The suspension is allowed to gently mix at 95 C for 90 minutes.Afterwards, the liquid is decanted from the solids. Then the solids arewashed with sufficient hexanes until residual peroxide content in thehexanes is less than 0.5%. The solids are then dried in vacuo at 50° C.until the solid weight no longer changes.

EXAMPLE 3

Preparation of Caustic Treatment Mixture.

A solution containing 79.1% w/w sodium sulfide nonahydrate and 20.9% w/wpropylene glycol is prepared. The mixture is heated to 50° C. to insurecomplete dissolution. The solution is stored in a warm water bath toprevent sulfide precipitation before further use.

EXAMPLES 4A AND 4B

Continuous Catalytic Heteroatom Oxidation

A water jacketed plug flow reactor with an aspect ratio(length/diameter) of 20 is filled with 171 grams of supported catalystprepared according to the method of example 2 containing about 0.4% w/wTi. The reactor temperature is stabilized at 95 C. An Athabasca bitumenfeed is warmed to 80 C under nitrogen in a stainless steel drum tofacilitate pumping into the reactor. The bitumen is combined with anexcess of tert-butylhydroperoxide solution in xylenes (40% w/w) toobtain a 6:1 molar ratio of peroxide to sulfur at the reactor inlet.

The solution is pumped into the reactor at a sufficient flow rate toobtain a liquid residence time of 90 minutes in the reactor. Samples arecollected periodically at the reactor outlet to measure peroxideconcentration. The reactor effluent is continuously distilled undervacuum to remove all residual peroxide, tert-butanol, and xylenes and toobtain an oxidized heteroatom bitumen stream.

Example 4B is the same as 4A except that the reactor temperature isincreased to 115° C.

EXAMPLE 5A AND 5B

Caustic Treatment of Example 4 Output

The oxidized heteroatom bitumen stream of Example 4A and 4B areindependently co-fed with the mixture of Example 3 into a continuouslystirred tank reactor (CSTR) so as to obtain a liquid residence time of90 minutes at 275° C. under 300 psig. The reactor effluent flows into agravity settler producing an oil phase and a spent caustic phase. Theoil product is separated from the spent caustic phase. The properties ofthe products of 4A, 4B, 5A,5B and the hydrocarbon feed may be comparedand characterized by the IR spectroscopy printout depicted in FIG. 7 ato FIG. 7 e.

While this disclosure has been described in conjunction with thespecific embodiments outlined above, it is evident that manyalternatives, modifications and variations will be apparent to thoseskilled in the art. Accordingly, the preferred embodiments of thepresent disclosure as set forth above are intended to be illustrative,not limiting. Various changes may be made without departing from thespirit and scope of the invention, as required by the following claims.The claims provide the scope of the coverage of the invention and shouldnot be limited to the specific examples provided herein.

What is claimed is:
 1. A hydrocarbon composition comprising: at least0.1 grams per gram of hydrocarbon product having a boiling rangedistribution from an initial boiling point to approximately 739° C.; aninfrared spectroscopy reference peak, centered between approximately1445 cm⁻¹ and 1465 cm⁻¹; a first infrared spectroscopy peak betweenapproximately 1310 cm⁻¹ and 1285 cm⁻¹, wherein the height or area of thefirst infrared spectroscopy peak is at least approximately 28% of theheight or area of the infrared spectroscopy reference peak; and a secondinfrared spectroscopy peak between approximately 1135 cm⁻¹ and 1110cm⁻¹, wherein the height or area of the second infrared spectroscopypeak is at least approximately 22% of the height or area of the infraredspectroscopy reference peak.
 2. The hydrocarbon composition of claim 1,further comprising a third infrared spectroscopy peak betweenapproximately 1040 cm⁻¹ and 1000 cm⁻¹, wherein the height or area of thethird infrared spectroscopy peak is at least approximately 22% of theheight or area of the infrared spectroscopy reference peak.
 3. Thehydrocarbon composition of claim 1 wherein at least 0.4 grams per gramof hydrocarbon product has a boiling range distribution from an initialboiling point to approximately 739° C.
 4. The hydrocarbon composition ofclaim 1, wherein the hydrocarbon composition has a total acid numberless than 0.5 mg KOH per gram of hydrocarbon product.
 5. The hydrocarboncomposition of claim 1, wherein the viscosity of the hydrocarboncomposition is less than the viscosity of a hydrocarbon feed from whichthe hydrocarbon composition is derived, at 80° C.
 6. The composition ofclaim 1, wherein the viscosity of the hydrocarbon composition is lessthan the viscosity of a hydrocarbon feed from which the hydrocarbonproduct is derived, at 15° C.
 7. The hydrocarbon composition of claim 1,wherein the API gravity is at least
 12. 8. The hydrocarbon compositionof claim 1, wherein the composition has a sulfur content of less than6.0 weight percent (wt %).
 9. The hydrocarbon composition of claim 1,wherein the composition has a nitrogen content of less than 0.2 wt %.10. The hydrocarbon composition of claim 1, wherein the composition hasan oxygen content of less than 1.2 wt %.
 11. The hydrocarbon compositionof claim 1, wherein the infrared spectroscopy reference peak is measuredneat by attenuated total reflectance Fourier Transform infraredSpectroscopy.
 12. A hydrocarbon product comprising: at most 0.3 gramsper gram of the hydrocarbon product is insoluble in n-heptane; at least0.1 grams per gram of the hydrocarbon product has a boiling pointgreater than 738° C.; an infrared spectroscopy reference peak, centeredbetween approximately 1445 cm⁻¹ and 1465 cm⁻¹; an infrared spectroscopypeak between approximately 1040 cm⁻¹ and 1000 cm⁻¹, wherein the heightor area of the second infrared spectroscopy peak is at leastapproximately 22% of the height or area of the infrared spectroscopyreference peak; and a second infrared spectroscopy peak betweenapproximately 1135 cm⁻¹ and 1110 cm⁻¹; wherein the height or area of thefirst infrared spectroscopy peak is at least approximately 22% of theheight or area of the infrared spectroscopy reference peak.
 13. Thehydrocarbon product of claim 12 further comprising a third infraredspectroscopy peak between approximately 1310 cm⁻¹ and 1285 cm⁻¹, whereinthe height or area of the third infrared spectroscopy peak is at leastapproximately 28% of the height or area of the infrared spectroscopyreference peak.
 14. The hydrocarbon product of claim 12, wherein thetotal acid number of the hydrocarbon product is less than a hydrocarbonfeed from which the hydrocarbon product is derived.
 15. The hydrocarbonproduct of claim 12, wherein the viscosity at 80° C. is less than theviscosity of the hydrocarbon feed.
 16. The hydrocarbon product of claim12, wherein the viscosity measured at 15° C. is less than the viscosityof the hydrocarbon feed.
 17. The hydrocarbon product of claim 12,wherein the density is less than 1.05 g/cc at 15° C.
 18. The hydrocarbonproduct of claim 12, wherein the density at 80° C., 100° C. and 120° C.provides an implied density of less than 1.05 g/cc when extrapolated to15° C.
 19. The hydrocarbon product of claim 12, wherein the sulfurcontent is less than the hydrocarbon feed.
 20. The hydrocarbon productof claim 12, wherein the nitrogen content is less than the hydrocarbonfeed.
 21. The hydrocarbon product of claim 12, wherein the hydrocarbonproduct has a metal content less than the metal content of thehydrocarbon feed.
 22. The hydrocarbon product of claim 12, wherein thehydrocarbon product has a total acid number of less than 0.5 mg KOH pergram of hydrocarbon product.
 23. A hydrocarbon product comprising: 0.01to 0.25 grams of hydrocarbons per gram of the hydrocarbon product havinga boiling range distribution from an IBP to approximately 204° C.; aninfrared spectroscopy reference peak, centered between approximately1445 cm⁻¹ and 1465 cm⁻¹; a first infrared spectroscopy peak betweenapproximately 1310 cm⁻¹ and 1285 cm⁻¹, wherein the height or area of thethird infrared spectroscopy peak is at least approximately 28% of theheight or area of the infrared spectroscopy reference peak; and a secondinfrared spectroscopy peak between approximately 1040 cm⁻¹ and 1000cm⁻¹, wherein the height or area of the second infrared spectroscopypeak is at least approximately 22% of the height or area of the infraredspectroscopy reference peak.
 24. The hydrocarbon product of claim 22,further comprising a third infrared spectroscopy peak betweenapproximately 1135 cm⁻¹ and 1110 cm⁻¹, wherein the height or area of thethird infrared spectroscopy peak is at least approximately 22% of theheight or area of the infrared spectroscopy reference peak
 25. Thehydrocarbon product of claim 22, wherein sulfur content is less than 6.0wt %.
 26. The hydrocarbon product of claim 22, wherein the nitrogencontent is less than 0.3 wt %.
 27. The hydrocarbon product of claim 22,wherein the oxygen content is less than 1.25 wt %.